System and method for an automated subsea testing unit

ABSTRACT

A system to test barrier pressure includes a Christmas Tree (XT) coupled to a wellbore including a downhole pressure barrier. The XT includes a first valve along a flow path and a second valve coupled to the flow path. The system further includes a testing unit that includes a vessel fluidly coupled to the flow path. The testing unit also includes a fluid mover associated with the vessel to draw fluid into or to drive fluid out of the vessel. The testing unit further includes an actuator coupled to the fluid mover to control operation of the fluid mover. The testing unit is configured to draw a volume of fluid out of the XT and to further return the volume of fluid to the XT.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63/349,424, filed Jun. 6, 2022, and titled “SYSTEM AND METHOD FOR AN AUTOMATED SUBSEA TESTING UNIT,” the full disclosure of which is hereby incorporated by reference in its entirety for all purposes.

BACKGROUND 1. Field of the Disclosure

The present disclosure relates to wellbore operations. Specifically, the present disclosure relates to systems and methods for remote testing of barriers, such as barriers formed in subsea wellbores.

2. Description of Related Art

Testing of remotely located barriers, such as valves associated with wellbores that may be used for oil and gas recovery, carbon dioxide injection, and the like, may be necessary in certain situations. In one scenario, formation pressures may be too low to generate significant differential pressure between components for inflow testing. Additionally, there may be limited or no fluid supplies as an alternative means to provide sufficient pressures for these tests. As a result, testing may be expensive or challenging, or may cause environmental risks.

SUMMARY

Applicant recognized the problems noted above herein and conceived and developed embodiments of systems and methods, according to the present disclosure, for pressure barrier testing.

In an embodiment, a system to test barrier pressure includes a Christmas Tree (XT) coupled to a wellbore, the wellbore including a downhole pressure barrier. The XT includes a first valve along a flow path. The XT also includes a second valve coupled to the flow path. The system further includes a testing unit that includes a vessel fluidly coupled to the flow path, wherein the second valve is between the vessel and the first valve. The testing unit also includes a fluid mover associated with the vessel to draw fluid into or to drive fluid out of the vessel. The testing unit further includes an actuator coupled to the fluid mover to control operation of the fluid mover. The testing unit is configured to draw a volume of fluid out of the XT in response to a command to perform a pressure test on at least one pressure barrier, the testing unit to further return the volume of fluid to the XT after completion of the pressure test.

In an embodiment, a method includes determining one or more barriers for pressure testing. The method also includes operating one or more valves to isolate the one or more barriers. The method further includes causing a fluid mover to draw a quantity of fluid into a vessel. The method includes conducting one or more pressure testing operations. The method also includes causing the fluid mover to drive the quantity of fluid out of the vessel after completion of the one or more pressure testing operations.

In an embodiment, a system to test barrier pressure includes a well component including at least a first valve and a second valve arranged along a flow path, the flow path being coupled to a well. The system also includes a downhole pressure barrier positioned in the well. The system further includes a vessel fluidly coupled to the well component. The system also includes a controllable fluid mover associated with the vessel, the controllable fluid mover configured to decrease a pressure within the vessel to draw a fluid into the vessel along the flow path and to increase a pressure within the vessel to drive the fluid out of the vessel along the flow path.

In an embodiment, a system to test barrier pressure includes a Christmas Tree (XT) coupled to a wellbore and a testing unit. The wellbore includes a downhole pressure barrier. The XT includes a master valve along a flow path. The XT also includes a wing valve coupled to the flow path, the wing valve being fluidly coupled to a fluid source for injecting a fluid into the XT. The XT further includes an access valve coupled to the flow path. A testing unit includes a vessel fluidly coupled to the access valve. The testing unit also includes a fluid mover associated with the vessel to draw fluid into or to drive fluid out of the vessel. The testing unit further includes an actuator coupled to the fluid mover to control operation of the fluid mover. The testing unit is configured to draw a volume of fluid out of the XT in response to a command to perform a pressure test on at least one pressure barrier, the testing unit to further return the volume of fluid to the XT after completion of the pressure test.

In an embodiment, a method includes determining one or more downhole barriers for pressure testing. The method also includes operating one or more valves to isolate the one or more downhole barriers. The method further includes causing a fluid mover to draw a quantity of fluid into a vessel. The method also includes causing the fluid mover to drive the quantity of fluid out of the vessel after completion of the pressure testing.

A system to test barrier pressure includes a fluid system associated with a wellbore and a testing unit. The wellbore includes a downhole pressure barrier. The fluid system includes a first valve along a flow path, a second valve coupled to the flow path, the second valve being fluidly coupled to a fluid source for injecting a fluid into the fluid system, and a third valve coupled to the flow path. The testing unit includes a vessel fluidly coupled to the third valve, a fluid mover associated with the vessel to draw fluid into or to drive fluid out of the vessel, and an actuator coupled to the fluid mover to control operation of the fluid mover. The testing unit is configured to draw a volume of fluid out of the fluid system in response to a command to perform a pressure test on at least one pressure barrier, the testing unit to further return the volume of fluid to the fluid system after completion of the pressure test. The fluid system may include at least portion of one or more of a Christmas tree (XT), a manifold, a downhole portion within the wellbore, or a wellhead associated with the wellbore.

BRIEF DESCRIPTION OF DRAWINGS

The present technology will be better understood on reading the following detailed description of non-limiting embodiments thereof, and on examining the accompanying drawings, in which:

FIG. 1 is a schematic side view of an embodiment of an offshore drilling operation, in accordance with embodiments of the present disclosure;

FIG. 2 is a schematic diagram of an embodiment of a testing environment that includes an embodiment of a Christmas Tree (XT) and an embodiment of a testing unit, in accordance with embodiments of the present disclosure;

FIG. 3 is a schematic diagram of an embodiment of a testing environment that includes an embodiment of a Christmas Tree (XT) and an embodiment of a testing unit, in accordance with embodiments of the present disclosure;

FIG. 4 is a schematic diagram of an embodiment of a testing environment that includes an embodiment of a Christmas Tree (XT) and an embodiment of a testing unit, in accordance with embodiments of the present disclosure;

FIG. 5 is a schematic diagram of an embodiment of a testing environment that includes an embodiment of a Christmas Tree (XT) and an embodiment of a testing unit, in accordance with embodiments of the present disclosure

FIG. 6 is a schematic diagram of an embodiment of a testing environment that includes an embodiment of a Christmas Tree (XT) and an embodiment of a testing unit, in accordance with embodiments of the present disclosure; and

FIG. 7 is a flow chart of an embodiment of a process for performing a pressure barrier test, in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

The foregoing aspects, features, and advantages of the present disclosure will be further appreciated when considered with reference to the following description of embodiments and accompanying drawings. In describing the embodiments of the disclosure illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.

When introducing elements of various embodiments of the present disclosure, the articles “a”, “an”, “the”, and “said” are intended to mean that there are one or more of the elements. The terms “comprising”, “including”, and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Any examples of operating parameters and/or environmental conditions are not exclusive of other parameters/conditions of the disclosed embodiments. Additionally, it should be understood that references to “one embodiment”, “an embodiment”, “certain embodiments”, or “other embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, reference to terms such as “above”, “below”, “upper”, “lower”, “side”, “front”, “back”, or other terms regarding orientation or direction are made with reference to the illustrated embodiments and are not intended to be limiting or exclude other orientations or directions. It should be further appreciated that terms such as approximately or substantially may indicate +/−10 percent.

Embodiments of the present disclosure are directed toward systems and methods for an automated testing unit (e.g., an automated subsea testing unit) (ATU/ASTU) for periodic barrier testing for downhole systems, including but not limited to subsea carbon dioxide (CO₂) injection systems in carbon capture and storage (CCS) applications, among various other applications. Various embodiments enable remote testing where inflow testing is challenging due to low reservoir back pressure. Systems and methods may create differential pressure in the system (e.g., a wellbore that includes a Christmas tree (XT)) by drawing a volume of fluid from the XT, using a piston in a vessel actuated (e.g., electrically) by a rotary electric actuator (REA) and/or rotary to linear motion device (RLM). It should be appreciated that such systems are provided by example and various other drive mechanisms may be utilized for movement of the piston (which may be linear movement in certain embodiments, but is not limited to linear movement), including but not limited to, linear hydraulic actuators, linear pneumatic actuators, linear electric motors, solenoid arrangements, various mechanical, electric, or pneumatic drive systems, and the like. Accordingly, systems and methods may be described in terms of linear movement with respect to a piston, but such examples are not intended to limit the scope of the present disclosure in that other drive systems may also be incorporated to move a piston and/or some other device to increase and/or decrease a volume. Systems and methods may then be used to replace fluid when testing is complete, and as a result, there may be no need to retrieve or manage the volumes of fluid. Furthermore, the vessel arrangement prevents the need to vent process fluid to sea, thereby providing a positive environmental advantage.

Embodiments of the present disclosure may be related to an ASTU for periodic, remote testing of barriers in subsea CO₂ injection systems for CCS, among other various applications. Embodiments may also be used with directed and/or otherwise planned testing, for example using one or more subsea robots or the like to activate testing. The ASTU enables testing by drawing pre-determined fluid volumes from the XT and/or well to create differential pressures needed to test various valves and/or barriers associated with the well, such as valves on the XT (e.g., XT master valves, XT wing valves, etc.) and/or downhole safety valves. Such testing would not be possible without inflow testing in a variety of applications due to the limited reservoir back pressures of the wellbore. In at least one embodiment, the ASTU includes, at least in part, a vessel that has a moveable piston in it (e.g., linear movement along an axis of the vessel), that is electrically actuated by the RLM, connected to a subsea control system so that remote operations may be enabled. The piston may move inside the vessel to draw fluid out of the XT. It should be appreciated that a flow line may couple the vessel to the XT, for example, via a hot stab to a dedicated venting line, via a direct connection between the XT and the vessel, and/or the like. Incorporating the ASTU avoids venting of volumes of fluid to the sea (or to a surrounding environment in non-subsea applications), which is not environmentally desirable, and allows for the fluid to be replaced after testing is complete, for example, by reversing the motion of the piston. Accordingly, configurations of embodiments of the present disclosure also prevent the need for recovery of the unit for periodic emptying, further simplifying operations and reducing costs to operators.

Embodiments of the present disclosure provide significant cost savings to operators of these CO₂ injection systems in terms of both capital expenditure (CAPEX) and operating expenditure (OPEX). For example, various embodiments may eliminate the need for dedicated service lines or fluid lines in the umbilical to support valve testing operations, since fluid is also not typically required for chemical injection in these applications. Moreover, for all electric systems, embodiments also support efforts to replace expensive umbilicals with a simple power and communications cable for further cost savings. In terms of OPEX, embodiments may reduce or eliminate the need for support vessels to be frequently mobilized to support valve testing operations, which would otherwise be needed to supply fluid or to manage vented volumes.

Various embodiments of the present disclosure incorporate the ASTU within a subsea environment. It should be appreciated that the ASTU may also be deployed at surface environments, for example in remote locations, and may be referred to as ATUs in such cases, or also as ASTUs, with the understanding that the use of the term “subsea” does not limit embodiments to such applications unless otherwise specifically stated. The ASTU may include one or more components, which may be arranged as a collection or system with different configurations that may include more or fewer parts, and in various embodiments, may also include various support systems. In at least one embodiment, the ASTU includes a container or a vessel that has a piston in it, that is electrically actuated by the RLM, connected to the subsea control system, so that is may be remotely operated. The piston moves up inside the vessel to draw fluid out from the XT, to which it is connected, such as by a hot stab to a dedicated venting line or via a direct connection to one or more access ports, among other options. The stem of the piston may be threaded into the RLM and the RLM is used to convert the rotary motion of the REA into linear motion of the piston. Various embodiments may further utilize the REA motor position sensor for calibration points (e.g., open and closed on piston) which may provide calibrated piston pressures based on position. As a result, operations would be able to remotely draw off the required (e.g., a determined) amount of fluid from the closed system to create the differential pressure necessary to perform the test, which may change depending on the volumes involved for the valve being tested, and the well shut-in pressure, which will increase over time.

Embodiments, enable the fluid that has been drawn from the system to be replaced, without the need to periodically empty or recover the unit to surface with a support vessel, which may minimize or reduce operational cost. Various embodiments may be mounted on the XT, but it should be appreciated that the stab to connect to the vent line may be removed and wet parked if access to vent or annulus line is required. Moreover, the vessel or other components may be “hard piped” to the XT in a configuration that is removable in the event access through one or more ports associated with the vessel is needed. In at least one embodiment, such configurations may be used in embodiment where the vessel is maintained in a pressurized state (e.g., pressurized over a defined threshold) to account for temperature changes and the like.

Embodiments of the present disclosure address and overcome one or more problems with existing systems and operations associated with remote and/or subsea barrier testing. Testing of subsea XT valves or downhole safety valves in CO₂ Injection systems for CCS applications is problematic and challenging due to a number of reasons. Firstly, the formation pressures are relatively low, or there is not sufficient back pressure from the reservoir to perform inflow testing of these barriers, or to create a significant enough differential pressure for a good test. Indeed, for valves that seal in one direction (e.g., downhole safety valves with a flapper mechanism), code requirements state that valves shall be tested in the direction of flow (i.e. with high pressure on the reservoir side). One way to overcome this drawback is to vent fluid off from volumes in the XT and the well above the safety valve to create the differential pressures necessary to test these barriers. However, this is undesirable because the venting is often to the surrounding environment. The second issue is that there is typically no fluid supply to subsea CO₂ injection systems, which may have otherwise supported valve testing operations. Subsea CO₂ injection systems lend themselves to electric systems due to the long step-outs typically involved and typically do not require chemical injection to support operations (e.g., for hydrate inhibition). As such, opportunity for large cost savings to the operators of these fields exists through elimination of any fluid lines in an umbilical, which may be replaced with a simple power and communications cable, since fluid is not required for hydraulic supply or chemical injection. So, testing of barrier valves and safety valves, which are required on a periodic basis throughout life of field, may either be challenging due to low back pressure from the reservoirs, or incur a large operational cost due to the need to mobilize support vessels to inject fluid for valve testing operations or to manage vented fluid volumes. The frequency for testing may be high, especially in early life, with a large number of wells (which these developments have in terms of initial phases and expansion potential). Therefore the operational cost could be significant to deploy support vessels regularly, especially in remote regions or regions with little or no supporting offshore infrastructure and industry. Also, from an environmental standpoint, the purpose of these projects is to prevent CO₂ from being released into the atmosphere from emitting sources, so having a low carbon footprint is essential. Utilizing support vessels frequently will negatively add to the carbon footprint of the project itself, thus undermining its value and stated aim. Finally, venting CO₂ to sea from the well or XT in quantities small or large is not desirable from an environmental or societal point of view. Embodiments of the present disclosure address these and other drawbacks of present techniques in the industry

Embodiments provide a low cost solution that enables periodic, remote testing of barriers in subsea CO₂ injection wells, among other applications, overcoming the issues of low backflow pressure, among other problems, without the need for support vessels or to vent volumes of CO₂ and/or process fluid to sea, which is not desirable from an environmental or societal standpoint. Accordingly, systems and methods may be used in a variety of different applications, and are not limited to CCS, where low back pressure from reservoirs may exist and/or remote applications where it may be desirable to reduce costs or equipment used for intervention and testing.

Various embodiments of the present disclosure may refer to operations with respect to one or more XTs. It should be appreciated that such a disclosure is by way of example only and is not intended to limit the scope of the present disclosure. For example, various embodiments may be associated with manifolds, wellheads, wellbore components, or various other fluid systems. That is, the scope of the present disclosure may be extended to various systems associated with forming one or more pressure boundaries that includes a volume that may hold fluid and/or pressure. For example, a manifold may be associated with a wellhead, where the manifold includes piping having some volume that can be drawn out of the manifold to generate the differential pressures described herein. Furthermore, in various embodiments, at least a portion of a wellhead may have a volume that can be used to generate a differential pressure. Additionally, in at least one embodiment, a portion of the wellbore itself, such as a portion that is downhole with respect to surface location, may include a volume from which a differential pressure may be formed. Moreover, different XT configurations may be used, such as different configurations for vertical or horizontal XTs. Additionally, these different XTs may be particularly selected and specialized for given applications, but may include one or more common piping or valve configurations, such as a certain minimum number of barriers between the well and an outlet, as one example. Accordingly, while embodiments may refer to XTs having a particular configuration, it should be appreciated that this is by way of non-limiting example only.

FIG. 1 is a schematic view of an embodiment of a subsea operation 100. It should be appreciated that one or more features have been removed for clarity with the present discussion and that removal or inclusion of certain features is not intended to be limited, but provided by way of example only. Furthermore, while the illustrated embodiment describes a subsea drilling operation, it should be appreciated that one or more similar processes may be utilized for subsea well interventions of surface applications and, in various embodiments, similar arrangements or substantially similar arrangements described herein may also be used in surface applications. Furthermore, a drilling operation is only shown as an example of an offshore well and it should be appreciated that embodiments may be directed toward situations after the well has been drilled and may be in operation and/or after end of life when the wellbore has been converted to an alternative application, such as CO₂ injection. The drilling operation includes a vessel 102 floating on a sea surface 104 substantially above a wellbore 106. A wellbore housing 108 sits at the top of the wellbore 106 and is connected to a blowout preventer (BOP) assembly 110, which may include shear rams 112, sealing rams 114, and/or an annular ram 116. One purpose of the BOP assembly 110 is to help control pressure in the wellbore 106. The BOP assembly 110 is connected to the vessel 102 by a riser 118. During drilling operations, a drill string 120 passes from a rig 122 on the vessel 102, through the riser 118, through the BOP assembly 110, through the wellhead housing 108, and into the wellbore 106. It should be appreciated that reference to the vessel 102 is for illustrative purposes only and that the vessel may be replaced with a floating platform or other structure. The lower end of the drill string 120 is attached to a drill bit 124 that extends the wellbore 106 as the drill string 120 turns. Additional features shown in FIG. 1 include a mud pump 126 with mud lines 128 connecting the mud pump 126 to the BOP assembly 110, and a mud return line 130 connecting the mud pump 126 to the vessel 102. A remotely operated vehicle (ROV) 132 can be used to make adjustments to, repair, or replace equipment as necessary. Although a BOP assembly 110 is shown in the figures, the wellhead housing 104 could be attached to other well equipment as well, including, for example, a subsea Christmas tree (XT), a spool, a manifold, or another valve or completion assembly.

One efficient way to start drilling a wellbore 106 is through use of a suction pile 134. Such a procedure is accomplished by attaching the wellhead housing 108 to the top of the suction pile 134 and lowering the suction pile 134 to a sea floor 136. As interior chambers in the suction pile 134 are evacuated, the suction pile 134 is driven into the sea floor 136, as shown in FIG. 1 , until the suction pile 134 is substantially submerged in the sea floor 136 and the wellhead housing 108 is positioned at the sea floor 136 so that further drilling can commence. As the wellbore 106 is drilled, the walls of the wellbore are reinforced with concrete casings 138 that provide stability to the wellbore 106 and help to control pressure from the formation. It should be appreciated that this describes one example of a portion of a subsea drilling operation and may be omitted in various embodiments. In at least one embodiment, systems and methods of the present disclosure may be used for drilling operations that are completed through a BOP and wellhead, where a casing hanger and string are landed in succession.

Embodiments of the present disclosure are directed toward an automated subsea testing unit (ASTU) (e.g., subsea testing unit, automated testing unit, testing unit, etc.) that may be utilized in one or more environments, such as a subsea environment or a remote environment. FIG. 2 is a schematic diagram of an embodiment of a subsea environment 200 in which the present disclosure may be used. In this example, the subsea environment 200 includes an Christmas Tree (XT) 202 that coupled to a wellhead 204 or/or a wellhead component, such as a tubing hanger, of a wellbore 206 extending into a formation. As noted above, the XT 202 is provided by way of non-limiting example only and may, in various other embodiments, be replaced with one or more additional fluid systems that may include valves, piping, instruction, and the like sufficient to create a volume from which to draw fluid and/or pressure to generate a differential pressure. Furthermore, the illustration of a vertical XT (VXT) is also by way of example and not intended to limit the scope of the present disclosure, as systems and methods may also be adapted to horizontal XTs and various other piping configurations. In one or more embodiments, the XT 202 may be replaced with a manifold, portions of the wellhead 204, various piping configurations, portions of the wellbore 206, or the like. The wellbore 206 includes a tubing 208 (e.g., casing, production tubing, injection tubing, etc.) and an annulus 210 formed around the tubing 208 defined by the wellbore wall. In this example, a downhole safety valve (DHSV) 212 is arranged along the tubing 208, but it should be appreciated that the DHSV 212 may be associated with the wellbore itself and may be positioned to effectively seal the wellbore, including both the tubing 208 and the annulus 210. Additionally, in this example, a separate annulus isolation device (AID) 214 is also shown. As will be appreciated, various isolation devices may be utilized in line with various codes and regulations, such as those to provide at least two pressure barriers between the formation and an access point.

It should be appreciated that the arrangement of the XT 202, including the positions or numbers of valves, flow paths, and the like, is provided by way of example only and that embodiments of the present disclosure may be utilized with trees having a number of different configurations. Additionally, various types of valves, piping, fittings, and the like may be incorporated within the scope of the present disclosure. For example, different valve types may be used, such as ball vales, gate valves, needle valves, globe valves, and/or the like. Furthermore, it should be appreciated that the XT 202 may be a particularly selected XT 202 for use with a CO₂ injection, or may be a standard tree that has been modified or otherwise retrofitted for CO₂ injection, among other options. In this configuration, a master valve 216 (MV or IMV) is arranged along a flow path 280 of the XT 202 (e.g., along a path coupled to the tubing 208). While a single master valve 216 is shown, other embodiments may include an upper master valve and a lower master valve or a master valve and a swab valve, among other configurations and options. The flow path continues along to a tree cap 218 and a wing valve (WV or IWV) 220, which may be coupled to a production vessel 222 to receive fluids produced from the formation. In various embodiments, the flow path 280 may include one or more branches and/or portions. For example, a first part of the flow path 280 may extend between the wellbore 206 and the master valve 216 while a second part may extend from the master valve 216 to the wing valve 220. Furthermore, as noted herein, embodiments are directed toward a particular XT configuration for simplicity, but it should be appreciated that, in various embodiments, one or more portions may be modified, such as to permit CO₂ injection into the wellbore 206. For example, in at least one embodiment, the production vessel 222 may be replaced by a source to direct flow into the wellbore 206. As noted above, different configurations may include more or fewer valves, which may have different flow paths or alternative routing, and that the example provided herein is for illustrative purposes only and not intended to limit the scope of the present disclosure.

The illustrated XT 202 further includes an annulus flow path 282 associated with the AID 214 coupled to the annulus 210. Similar to the flow path 280, the annulus flow path 282 may include one or more branches, and moreover, may combine with the flow path 280 such that the combination of the annulus flow path 282 and the flow path 280 forms a flow path. Along the flow path 282 is an annulus master valve (AMV) 224, which as noted above, may include additional valves other than the single valve illustrated in the example. The annulus flow path 282 continues to an annulus access valve (AAV) 226, which may also be referred to as a vent line and/or a port. A connecting flow path 284, which may also be considered as at least a portion of one or more of the flow path 280 and the annulus flow path 282, is shown that couples the annulus flow path 282 to the flow path 280 via a cross over valve (XOV) 228. As a result, flow between the annulus flow path 282 and the production flow path 280 may be provided via opening the XOV 228, thereby forming a common flow path, which may be referred to collectively as the flow path 280 with the understanding that different portions or branches of the flow path 280 may be fluidly coupled together after one or more valves are opened and/or closed.

Embodiments of the present disclosure are directed toward the ASTU 230, which in this example is coupled to the annulus flow path 282, and therefore can be further connected to the flow path 280, via a hot stab at the vent on a downstream (relative to a direction to flow out of the XT 200) side of the AAV 226. It should be appreciated that the position of the ASTU 230 is provided by way of non-limiting example only to assist with the present discussion. It should be appreciated that the ASTU 230 may be coupled to a variety of different locations along the XT 202 to permit testing of various pressure barriers. Additionally, the use of the hot stab is also by way of non-limiting example and different coupling mechanisms may be utilized, for example, the ASTU 230 may be part of a spool that is formed within the XT 202 and/or may be integrally formed within the XT 202, among other options. As another example, one or more components of the ASTU 230 may be mounted to the XT 202 and may be hard-piped or otherwise rigidly connected to one or more ports or vents, where further embodiments may permit removal of the ASTU 230, or components thereof, responsive to needs regarding access via the one or more ports or vents.

The illustrated ASTU 230 includes a vessel 232, a fluid mover 234, and an actuator 236 (which in this example is a RLM, but such an actuator is provided by way of example only and not to limit different types of actuators that may be used to drive movement of the fluid mover 234), which may be used to drive the fluid mover 234. Additionally, a flow line 238 couples the hot stab to the XT 202, where the flow line 238 permits flow both into and out of the vessel 232. As noted herein, embodiments may eliminate the flow line 238 and/or the flow line may be replaced with hard piping or a connection between the vessel 232 and the XT, for example at an outlet of one or more valves or along the annulus flow path 282 and/or the connecting flow path 284. In this example, the fluid mover 234 is a piston positioned within the vessel 232. The piston may be driven to move linearly along a vessel axis such that movement in a first direction (e.g., a downward direction based on the configuration of FIG. 2 toward an opening of the vessel 232) decreases a vessel volume and in a second direction (e.g., an upward direction based on the configuration of FIG. 2 away from the opening of the vessel 232) to increase a vessel volume. Movement may be driven by the actuator 236, which in this example includes a rotary electric actuator (REA) coupled to a rotary to linear motion device (RLM). As noted above, such a system may be an electrically powered system that eliminates the use of additional support equipment, such as hydraulic fluids to drive movement of the piston. It should be appreciated that embodiments of FIG. 2 are shown by way of example only and that different actuators 236 and fluid movers 234 may be used, such as linear actuators, hydraulic actuators, electric motors, solenoid arrangements, pumps, and the like. Moreover, one or more ROVs may be used to actuate the fluid mover 234.

Various embodiments of the present disclosure may include one or more combinations of fluid movers 234 and/or actuators 236 to drive fluid (e.g., gases, liquids, solids, or combinations thereof) into and/or out of the vessel 232. In at least one embodiment, the fluid movers 234 may be used to increase or decrease a pressure within the vessel 232, such as the embodiment noted herein where a piston may increase or decrease a volume within the tank. Additionally, various embodiments may not include the fluid mover 234 within the vessel 232. For example, the fluid mover 234 may be an electric pump that is used to drive fluid into the vessel 232 and/or to drive fluid out of the vessel 232.

As will be described below, in operation, the ASTU 230 may be used to remove a volume of fluid from the XT 202 and/or the wellbore 206 in order to create a differential pressure for barrier testing. For example, piston movement in a first direction draws fluid into the vessel 232 and piston movement in a second direction may drive fluid out of the vessel 232 and back into the XT 202 and/or the wellbore 206. As a result, differential pressures may be created in a direction of fluid flow, which may be useful for testing the DHSV 212 when formation pressures are insufficient. Additionally, various embodiments further provide for a method that uses fluid already within the XT 202 and/or the wellbore 206 to generate the differential pressure and then replaces the fluid after testing, thereby reducing a need to have support equipment, such as ships, come and periodically empty the vessel 232. For example, the vessel 232 may be empty or substantially empty such that it is prepared to receive a fluid volume. It should be appreciated that the volume of the vessel 232 may be particularly selected based, at least in part, on an expected fluid volume to be received. For example, the vessel size may be based on a volume within the XT 202 and/or the wellbore 206 and also on expected operating conditions in order to determine a quantity of fluid to draw into the vessel 232 to generate a desired differential pressure. Additionally, various embodiments may also maintain a volume of fluid within the vessel 232 to pressure the vessel 232 to account for various temperature changes and the like.

The stem of the piston may be threaded into the RLM and the RLM may be used to convert the rotary motion of the REA into linear motion of the piston. Utilizing the REA motor position sensor for calibration points (e.g., open and closed on piston) may be used to obtain calibrated piston pressures based on position, which may enable the operator to draw the correct amount of fluid depending on the barrier being tested (e.g., XT valves or the DHSV 212). In at least one embodiment, a controller 240, which may be part of the subsea controller that may be integrated into or separate from the XT 202, may receive one or more signals, such as from various gauges, such as a pressure transducer 242 in order to determine a differential pressure within the XT 202 and/or other location and, based on this information, may control a position of the fluid mover 234 within the vessel 232.

As noted, various embodiments may further include additional piping configurations, valves, sensors, and the like. For example, in this example, a choke 244 (CV or ICV) and a flow valve 246 (FV or FIV) are arranged downstream (in embodiments where flow is out of the wellbore 206) of the WV 220. Additionally, in the illustrated embodiment, an annulus wing valve (AWV) 248 is arranged between the AMV 224 and the AAV 226. Additional valves, such as the swab valves (SV, ASV, ISV) 250, 252 may also be utilized in various embodiments.

Various embodiments may be used for pressure testing of one or more barriers associated with the environment 200, such as various valves of the XT 202 and/or barriers associated with the wellbore 206, such as the IMV 216. FIG. 3 is a schematic diagram of an embodiment of an XT valve testing environment 300 in which features of the present disclosure may be used. In this example, the XT valves are tested using the ASTU 230. It should be appreciated that various call outs to specific valves and their position (e.g., open or closed) is by way of example using the illustrated XT configuration and that in other embodiments different configurations may be utilized within the scope of the present disclosure.

In this example, a testing procedure may be utilized where the FIV 246 is in a closed position, thereby isolating the wellbore 206. In at least one embodiment, this step may be referred to as shutting in or isolating the well and may include shutting one or more additional valves that may provide fluid communication to the well. The illustrated embodiment also shows the MV 216 in the closed position. As a result, pressure below the MV 216 will be shut-in pressure, which is dictated by reservoir conditions. Also shown in this example is the AMV 224 in the closed position, which further shuts in the well with respect to the reservoir.

The illustrated embodiment may then include steps such as opening the XOV 228 and the AAV 226, thereby providing a fluid pathway to the vessel 232. For example, fluid may flow through the flow path 280, the annulus flow path 282, and/or the connecting flow path 284, which as noted above, may generally be referred as using the flow path 280 or portions thereof. The actuator 236 may then be used to drive the fluid mover 234 in a second direction to increase the volume of the vessel 232, thereby drawing fluid into the vessel 232 and out of the XT 202. This fluid may be drawn from the cavity of the XT 202 and may, in various embodiments, be calculated or determined by the controller in order to provide a desired pressure differential across one or more valves. In this configuration, after movement of the fluid mover 234 to increase the vessel volume, a differential pressure exists across the MV 216 and the WV 220 as per testing requirements. This pressure may be maintained for any period of time per testing requirements. For example, the XOV 228 may be closed and pressure in the XT cavity may be monitored in order to simultaneously verify both the MV 216 and the WV 220. After testing is completed, various valves and components may be operated to push the fluid out of the vessel 232 and back into the XT 202. For example, the XOV 228 may be opened, the actuator 236 may drive the fluid mover 234 in a direction to reduce a volume of the vessel 232, the fluid may then flow through the AAV 226 and through the XOV 228 back into the XT 202, such as long the connecting flow pth 284 and/or the flow path 280. In this manner, testing may be accomplished without venting the fluid to the environment and without holding fluid within the vessel 232 (or without holding more than a threshold amount of fluid within the vessel 232), which may be emptied or substantially emptied to return the fluid back to the XT cavity, thereby reducing a need for support vessels to come to the site to periodically empty the vessel 232.

Various embodiments may be used for pressure testing of one or more barriers associated with the environment 200, such as various valves of the XT 202 and/or barriers associated with the wellbore 206, such as the DHSV 212. FIG. 4 is a schematic diagram of an embodiment of a DHSV testing environment 400 in which features of the present disclosure may be used. In this example, the DHSV 212 is tested using the ASTU 230. It should be appreciated that various call outs to specific valves and their position (e.g., open or closed) is by way of example using the illustrated XT configuration and that in other embodiments different configurations may be utilized within the scope of the present disclosure.

In this example, a testing procedure may shut in or isolate the well and may include shutting one or more additional valves that may provide fluid communication to the well. For example, the well may be shut in with the IWV 220. The illustrated embodiment, the DHSV 212 is moved to a closed position, where pressure below valves will be shut-in pressure, dictated by reservoir conditions. Next, both the XOV 228 and the AAV 226 may be opened, thereby providing a fluid path to the vessel 232. As noted, the fluid path may refer to the flow path 280, the flow path 282, the flow path 284, and/or combinations thereof. It should be appreciated that, when compared to FIG. 3 , the MV 216 is maintained in the open position in the configuration of FIG. 4 . In this configuration, the actuator 236 may be used to drive movement of the fluid mover 234 to increase a volume of the vessel 232, thereby drawing pressure from the XT 202, which creates a differential pressure across the DHSV 212. Advantageously, the differential pressure is considered to be on the reservoir side (e.g., in the direction of flow), and as a result, complies with various testing standards. Thereafter, the XOV 228 and/or the AAV 226 may be closed and pressure may be monitored, for example at the pressure transducer 242, among other options, to verify the DHSV 212. Upon completion of testing, the actuator 236 may drive movement of the fluid mover 234 to decrease a volume of the vessel 232 and return the fluid to the XT 202. In this manner, testing may be accomplished without venting the fluid to the environment and without holding fluid within the vessel 232 (or holding less than a threshold amount), which may be emptied and/or substantially emptied to return the fluid back to the XT cavity, thereby reducing a need for support vessels to come to the site to periodically empty the vessel 232.

Various embodiments may be used for pressure testing of one or more barrier associated with the environment 200, such as various valves of the XT 202 and/or barriers associated with the wellbore 206, such as the IWV 220. FIG. 5 is a schematic diagram of an embodiment of an DHSV testing environment 500 in which features of the present disclosure may be used. In this example, the IWV 220 is tested using the ASTU 230. It should be appreciated that various call outs to specific valves and their position (e.g., open or closed) is by way of example using the illustrated XT configuration and that in other embodiments different configurations may be utilized within the scope of the present disclosure.

In this example, a testing procedure may be utilized where the well is shut in, such as by closing the FIV 246. The illustrated embodiment, the DHSV 212 is shown in an open position. Next, both the XOV 228 and the AAV 226 may be opened, along with the IMV 216, thereby providing a fluid path to the vessel 232. In this configuration, the actuator 236 may be used to drive movement of the fluid mover 234 to increase a volume of the vessel 232, thereby drawing pressure from the XT 202, which creates a differential pressure across the IWV 220. Thereafter, the XOV 228 and/or the AAV 226 may be closed and pressure may be monitored, for example at the pressure transducer 240, among other options, to verify the DHSV 212. Upon completion of testing, the actuator 236 may drive movement of the fluid mover 234 to decrease a volume of the vessel 232 and return the fluid to the XT 202. In this manner, testing may be accomplished without venting the fluid to the environment and without holding fluid within the vessel 232 (or holding less than a threshold amount), which may be emptied or substantially emptied to return the fluid back to the XT cavity, thereby reducing a need for support vessels to come to the site to periodically empty the vessel 232.

Various embodiments of the present disclosure may further provide one or more configurations to permit utilization of the ASTU 230. In at least one embodiment, one or more components of the ASTU 230 may be directly coupled to the XT, for example at a port or vent. FIG. 6 is a schematic diagram of an embodiment of a testing environment 600 in which features of the present disclosure may be used. As described herein, various embodiments of the present disclosure may provide alternative methods or systems for coupling the vessel 232 to the XT 202, for example, via one or more ports or vents. While certain embodiments may include hot stabs extending into one or more portions of the flow path 280, connecting flow path 284, and/or annulus flow path 282, systems and methods may also hard pipe or directly connect the vessel 232 to one or more ports or vents of the XT. In the example of FIG. 6 , direct connection of the vessel 232 may enable omission or removal of one or more components, for example, the AAV 226. Furthermore, various systems or methods may also enable removal of the vessel 232 and/or access through the vessel 232 to the vent or port in the event that certain access operations are required or desired. By way of example, the vessel 232 may include one or more openings to facilitate insertion of hot stab or other flow lines that can couple to the flow paths 282, 282, 284.

FIG. 7 is a flow chart of an example of a process 700 for conducting barrier testing. It should be appreciated that this process, and other processes discussed herein, may include more or fewer steps. Additionally, the steps may be performed in a different order, or in parallel, unless otherwise specifically stated. In this example, one or more barriers are determined for testing 702. For example, different barriers (e.g., valves) may have different testing requirements or different configurations for testing. As a result, a determination for which barriers are being tested may be used to isolate or otherwise prepare for testing. One or more valves may be operated to isolated the desired barriers 704. For example, one or more actuators may be utilized to move valves between open or closed positions, where these one or more actuators may be remotely controllable. As a result, different configurations may block or permit fluid flow along various flow paths.

In at least one embodiment, a fluid mover may draw a quantity of fluid into a vessel 706. The quantity of fluid may be from a volume or space within the XT, among other options, and may be used to generate a differential pressure across the one or more barriers being tested. In at least one embodiment, an actuator may be used to drive a fluid mover within a vessel such that a vessel volume is increased, thereby permitting fluid to enter the vessel. In various embodiments, the quantity of fluid is determined based, at least in part, on a desired differential pressure. It should be appreciated that the volume may be a factor of various components, which may change over the life of the formation. For example, in a CO₂ injection well, formation pressure may increase over time as more CO₂ is injected. As such, volumes used in early stages may change compared to volumes in late stages. Various embodiments may include a controller to adjust a position of the fluid mover, such as a piston, based on pressure information that is monitored within the XT. For example, volume may be increased to generate more differential pressure based on pressure readings. In this manner, the volume may be dynamically changed to also change the differential pressure.

Pressure testing may be conducted on the one or more downhole barriers 708. This may include opening or closing various additional valves and also holding pressures for a period of time, among other options. Upon completion, the fluid mover may drive the fluid out of the vessel and back into the XT 710. For example, the fluid mover may move in an opposite direction as before to return the fluid to the XT, thereby reducing or eliminating a need for support equipment to empty the vessel and/or eliminating venting to the surrounding environment. In this manner, testing may be remotely performed using an automated system that may incorporate one or more electrical components that reduce use of expensive support equipment, such as additional hydraulic systems, and also maintains containment of various fluids utilized with the wellbore.

The foregoing disclosure and description of the disclosed embodiments is illustrative and explanatory of the embodiments of the disclosure. Various changes in the details of the illustrated embodiments can be made within the scope of the appended claims without departing from the true spirit of the disclosure. The embodiments of the present disclosure should only be limited by the following claims and their legal equivalents. 

1. A system to test barrier pressure, comprising: a Christmas Tree (XT) coupled to a wellbore, the wellbore including a downhole pressure barrier, the XT comprising: a first valve along a flow path; and a second valve coupled to the flow path; a testing unit, comprising: a vessel fluidly coupled to the flow path, wherein the second valve is between the vessel and the first valve; a fluid mover associated with the vessel to draw fluid into or to drive fluid out of the vessel; and an actuator coupled to the fluid mover to control operation of the fluid mover; wherein the testing unit is configured to draw a volume of fluid out of the XT in response to a command to perform a pressure test on the at least one pressure barrier, the testing unit to further return the volume of fluid to the XT after completion of the pressure test.
 2. The system of claim 1, wherein the fluid mover is a piston arranged within the vessel.
 3. The system of claim 2, wherein the actuator is an electrically driven rotary to linear motion device.
 4. The system of claim 1, wherein the pressure test is performed on at least one of the first valve or the downhole pressure barrier.
 5. The system of claim 1, further comprising: a third valve coupled to the flow path, the third valve being fluidly coupled to a fluid source for injecting a second fluid into the XT.
 6. The system of claim 5, wherein the fluid source is a carbon dioxide source.
 7. The system of claim 1, further comprising: a fourth valve positioned within a connecting flow path between the first valve and the second valve.
 8. The system of claim 1, wherein the testing unit is fluidly coupled to the XT via a hot stab.
 9. The system of claim 1, wherein the testing unit is directly coupled to the XT at one or more of a vent or a port.
 10. The system of claim 1, wherein the actuator is configured to be controlled by a subsea control system and the XT is a subsea XT.
 11. A method, comprising: determining one or more barriers for pressure testing; operating one or more valves to isolate the one or more barriers; causing a fluid mover to draw a quantity of fluid into a vessel; conducting one or more pressure testing operations; and causing the fluid mover to drive the quantity of fluid out of the vessel after completion of the one or more pressure testing operations.
 12. The method of claim 11, wherein the quantity of fluid is removed from a Christmas Tree (XT).
 13. The method of claim 12, further comprising: determining the quantity of fluid based, at least in part, on a differential pressure associated with the one or more barriers.
 14. The method of claim 12, wherein the quantity of fluid is returned to the XT after completion of the pressure testing.
 15. The method of claim 11, wherein the one or more barriers include at least one of a master valve or a downhole safety valve.
 16. The method of claim 11, wherein the pressure testing occurs in a subsea environment.
 17. A system to test barrier pressure, comprising: a well component including at least a first valve and a second valve arranged along a flow path, the flow path being coupled to a well; a downhole pressure barrier positioned in the well; a vessel fluidly coupled to the well component; and a controllable fluid mover associated with the vessel, the controllable fluid mover configured to decrease a pressure within the vessel to draw a fluid into the vessel along the flow path and to increase a pressure within the vessel to drive the fluid out of the vessel along the flow path.
 18. The system of claim 17, wherein the well component is one or more of a Christmas Tree (XT), a manifold, a wellhead, or a combination thereof.
 19. The system of claim 17, further comprising: a third valve arranged along the flow path, the third value positioned to regulate an inlet flow, into the flow path, from a fluid source.
 20. The system of claim 17, wherein the fluid is a gas, liquid, solid, or a combination thereof. 